Crushed Shale Samples Research Articles

An experimental investigation into the oxidative dissolution of typical organic-rich shale from China

Oxidizing stimulation of organic-rich shale was proposed to enhance the rate of methane extraction from the matrix. Previous studies lacked attention on the dissolution characteristics of organic matter (OM) during the dissolution process performed using oxidative fluids. In this study, the organic-rich shale samples obtained from the Longmaxi Formation, Niutitang Formation, and Yanchang Formation were used for dissolution experiments. Crushed shale samples were treated with deionized water, hydrogen peroxide (H2O2), or sodium hypochlorite (NaClO) for 240 h, respectively. By using a combination of X-ray Diffraction, rock-eval pyrolysis, total organic carbon analysis, X-ray photoelectron spectroscopy, and Fourier transform infrared spectroscopy, the composition and organic geochemical characteristics of the treated shale samples were determined. The results showed that H2O2 induces the dissolution of both the pyrite and carbonate minerals, and NaClO more readily dissolves pyrite and not carbonate minerals. Higher removal efficiency of OM for all four shale samples occurs when treated with NaClO than with H2O2. The oxidative dissolution of OM in these shale samples occurs as two dominant modes: one is the oxidation cracking of C–C, C–H such as in the Niutitang or Yanchange formations; the other is oxidation cracking of C–O, such as in the Longmaxi Formation samples. Both the Longmaxi Formation samples, which showed higher C–O contents compared to samples from the other two formations, exhibited better oxidizability than others when treated with H2O2 or NaClO. Oxidation products such as Fe2+/Fe3+ and H+ enhance the oxidizing ability of H2O2 and NaClO toward cracking of OM. However, the consumption of H+ due to the carbonate minerals may impair the oxidizing ability of H2O2, but not that of NaClO. Furthermore, the presence of an organo-clay complex has an adverse influence on the removal of OM. The results indicated that the type of OM, the content of the pyrite and carbonated minerals, and the physical protection of the organic carbon by clays should be taken into account, when selecting a shale reservoir suitable for oxidizing stimulation and associated optimization of the oxidant during the fracturing operation design.

Oxidative dissolution kinetics of organic-rich shale by hydrogen peroxide (H2O2) and its positive effects on improving fracture conductivity

Maintaining the fracture network created by hydraulic fracturing remains challenging because unpropped fractures close during production, resulting in shale gas production decline. Chemical dissolution is being implemented to maintain unpropped fracture conductivity, and the effect of oxidative dissolution on organic-rich shale may have the potential to maintain these fractures. In this paper, the change of organic matter (OM) in crushed shale samples exposed to hydrogen peroxide (H2O2) or deionized water were characterized. Reaction kinetics experiments were run using sliced shale samples and H2O2 with a mass concentration of 2–10% at temperature of 40–80 °C. Stress sensitivity of fractured shale plugs after oxidation for 72 h was evaluated. Results show H2O2 can remove 56.87% of solid OM and 55.34% of extractable OM in the crushed sample. Total organic carbon in H2O2 filtrate after the reaction is 91.36 mg/L,while that of deionized water is 30.88 mg/L. A significant decrease of C–O according to the C1s and O1s spectra of the crushed samples after oxidation means that some of oxygen contained functional groups oxidized and cleaved. However, reaction rate of oxidative dissolution occurs slowly and significantly depends on the concentration and temperature. The relationship between reaction rate and concentration can be described as a power function, and the relationship between reaction rate and temperature can be described as an exponential function. Activation energy of oxidative dissolution ranges from 3.51 to 12.10 kJ/mol when H2O2 mass concentration ranges from 2% to 10%. Oxidative dissolution can increase fracture width judging by estimation based on the mass loss. Stress sensitivity coefficient of the plugs treated with deionized water are 0.52 and 0.59, while the plugs treated with H2O2 are 0.48 and 0.52. It indicates that oxidative fluids can play a role in maintaining unpropped fracture conductivity enhancing shale gas recovery.

Experimental Study on the Pore Shape Damage of Shale Samples during the Crushing Process

Using crushed shale samples to obtain pore information from the gas adsorption experiments is a widely used method. Previous studies have evaluated the impact of the particle size on the pore size ...

The influence of moisture on the permeability of crushed shale samples

Shale cuttings and cores recovered from the subsurface and stored for hours to decades tend to dry out and lose moisture and hydrocarbons, leading to an increase in the effective matrix permeability. Moisture loss in shale samples is a fundamental sample preservation problem which can be solved by applying a standard moisture equilibration procedure to restore lost moisture. Our aim was to investigate the relationship between permeability and variable moisture as-received, as-received moisture-equilibrated and saturated moisture-equilibrated samples. Samples were crushed to a series of particle sizes (0.6-2.0) mm and moisture equilibrated at 97% relative humidity. Results show that moisture equilibration in the samples was achieved after 72 h. The permeability of the saturated moisture-equilibrated and as-received moisture-equilibrated samples decreased exponentially with increase in moisture content. The high correlation coefficient between permeability and particle size (r = 0.96 and 0.97) for moisture-equilibrated samples compared to 0.76 for as-received samples indicates that moisture equilibration improves permeability measurements in crushed shale samples. Furthermore, permeability measurements are repeatable for moisture-equilibrated samples compared to samples that were not equilibrated (as-received). We conclude that moisture content affects permeability and moisture equilibration normalizes and improves the repeatability of permeability measurements in crushed shale.

A method to determine the permeability of shales by using the dynamic process data of methane adsorption

Permeability is a critical parameter to evaluate the gas migration and development of shales, however, very difficult to get at the laboratory. Methane adsorption in shales is also an important factor of shales in natural state. A method of permeability that considers methane adsorption is described in this study. Permeability is derived from the dynamic data of the methane adsorption equilibrium process. The carboniferous shale samples, C01, C02, C03 and C04, were extracted from the eastern Qaidam Basin in China. The properties of the shales including organic/inorganic matter contents and pore size distribution were obtained by several techniques. Methane adsorption experiments were conducted on crushed shale samples over a pressure range up to 10 MPa and at a temperature of 313.15 K. Additionally, the permeability was calculated using the dynamic data at the adsorption equilibrium. Correlations between the permeability and methane adsorption and sample properties were discussed. The parameters of the calculation process were also analyzed.A parameter called the methane adsorption rate is defined as θ, which represents the variation in methane adsorption amount with pressure. The permeability is found to have the same variation trend with θ at experimental pressures before the inflection point. The pressure relative to the inflection point decreases with the micropore volume percentage, and the permeability increases with the methane adsorption affinity for the sample, nmax. We found that the permeability before the inflection point is considered to represent the micropores permeation property. The methane adsorption rate decreases to an infinitesimal value until the adsorption reaches a saturated state. The permeability values are assumed will stop fluctuating and become a fixed value, which we call kf. The parameter kf is regarded as the true permeability of the sample. The assumption gives a novel idea of permeability calculation. In addition, the permeability of the samples increases with the macropore volume, and the methane adsorption capacity nmax also increases with the total porosity.

Geotechnical Assessment of Crushed Shales from Selected Locations in Nigeria as Materials for Landfill Liners

Crushed shales obtained from two locations (Ahoko, Bida basin and Ifon, Dahomey basin) in Nigeria were evaluated to determine their suitability as compacted landfill liners. The shale samples were subjected to X-ray diffraction, hydraulic conductivity, classification, compaction, consolidation and cation exchange capacity tests. The result of the XRD revealed kaolinite and illite as the major clay minerals while quartz was the dominant non-clay minerals. The average CEC of Ifon and Ahoko shales was 5.37 and 8.34 mEq/100 g, respectively. The liquid limit, plastic limit and plasticity index of crushed Ifon shales ranged from (33.9 to 37.4%), (25.2 to 27.2%) and (8.6 to 10.2%) while the Ahoko shales ranged from (44 to 46.4%), (26.3 to 27.4%) and (16.6 to 19.6%), respectively. In addition, the estimated activity of the clay fractions of the two shales ranged from 0.41 to 0.51, suggesting inactive clays. The compacted shales have low compressibility and when compacted at modified Proctor level of compaction. At molding water content between optimum moisture content (OMC) ±2%, the hydraulic conductivities of the compacted shale were in the order of 10−6–10−7 cm/s when compacted at modified Proctor level. At OMC, hydraulic conductivities of the compacted shales were in the order of 10−7 cm/s when exposed to different concentration of calcium chloride solutions. Overall, the crushed shale samples from Ahoko and Ifon generally fulfilled the basic geotechnical properties for compacted clay liners.

Experimental investigation of shale gas production with different pressure depletion schemes

A matrix pressure depletion scheme can result in pore structure deformation and permeability reduction in shale, which affects the process of gas production in shale. Shale gas production tests were carried out with four core samples and with two crushed samples to investigate the effects of three different pressure depletion schemes on gas production rate and on ultimate gas recovery. The three pressure depletion schemes tested include constant production pressure, linear pressure decline, and step-wise pressure decline. Results of the gas production tests show that, for shale core samples, a production pressure depletion scheme affects not only gas production rate but also ultimate gas recovery. Pressure sensitivity tests of the four shale core samples were also performed, and the results show that permeability reduction of shale cores due to rapid pressure depletion caused the decrease in ultimate gas recovery. The gas production tests with crushed shale samples which were under zero effective stress show that a pressure depletion scheme only affects the gas production rate; that is, the same ultimate gas recovery was obtained for different pressure depletion schemes. The experimental results also show that the linear pressure decline and step-wise pressure decline depletion schemes delay the permeability reduction of the shale matrix, thereby resulting in a greater ultimate gas recovery than the constant production pressure scheme in which the production pressure was dropped immediately to an end value. In a step-wise pressure decline depletion scheme, in which gas diffusion and desorption were allowed to reach equilibrium at each pressure step, the ultimate gas recovery increases with a decrease in the size of the pressure step. However, in a linear pressure decline depletion scheme, the maximum ultimate gas recovery is obtained with that optimum pressure decline rate which causes the best match between the permeability reduction rate and the gas diffusion and desorption rates.

Water/Rock Interaction for Eagle Ford, Marcellus, Green River, and Barnett Shale Samples and Implications for Hydraulic-Fracturing-Fluid Engineering

Summary Knowledge of water/rock interactions on the surface of fractures is important to develop an understanding of the geological structures and changes within the formation, and to determine hydraulic-fracturing (HF) performance. To obtain this knowledge, this study investigates water/shale interactions in carbonate-rich (Eagle Ford), organic-rich (Green River), clay-rich (Barnett), and other-minerals-rich (Marcellus) shale samples. Crushed shale samples were exposed to water for 3 weeks at reservoir conditions. The water and rock samples before and after each static experiment were subjected to several analyses. The change in the rock mineralogy was defined by X-ray diffraction (XRD), the elemental composition of rock was determined by X-ray photoelectron spectroscopy (XPS) and scanning electron microscopy energy dispersive spectroscopy (SEM-EDS), and the organic content of rock samples was estimated by thermogravimetric analysis (TGA). The water was analyzed for its anions and cations, total dissolved solids (TDS), conductivity, pH, total organic carbon (TOC), and average particle sizes of colloids. The stability of the colloids was characterized by zeta-potential. We show that Barnett rock is high in illite content, and the greatest calcite concentration is determined for Eagle Ford. The sulfate content of water correlates with the atomic percent of the sulfur and oxygen elements determined through XPS analyses. The magnesium content of water correlates mainly with the illite amount in the rock, and calcium concentration associates with the calcite and gypsum content of the rock samples. The greatest dissolution rate belongs to the minerals that yield sulfate in the water; then, gypsum and calcite that yield calcium cation in the water come second; and the lowest dissolution rates are obtained from the magnesium-containing minerals (mainly, dolomite). TDS of the water samples shows that Green River has the least tendency to interact with water, and Barnett has the greatest tendency. Zeta-potential values indicate that particles in the water that interacted with Eagle Ford have the highest tendency for precipitation. The results of this study are used to make suggestions on the engineering of hydraulic-fracturing fluids (HFFs) in the context of water/rock interactions by considering the type and the concentration of ions along with colloidal stability determined through zeta-potential measurements.

A model of dynamic adsorption–diffusion for modeling gas transport and storage in shale

Understanding gas transport and storage processes is essential for analysis of reservoir accumulation mechanisms and evaluation of a shale formation. Because organic matter such as kerogen is widely distributed in shale, it plays an important role in gas diffusion and adsorption. Although many mathematical models considering gas diffusion and adsorption have been proposed and evaluated, very few models consider the effect of organic matter on the dynamic adsorption process, and research studies systematically combining a mathematical model history-matched to experimental data is also rare. In this study, a dynamic, approaching equilibrium (hereinafter referred to as “delayed”) adsorption–diffusion (DAD) method is presented to analyze gas transport and storage processes in crushed particles of three different sizes. The delayed effect for adsorption results from the dynamic mechanisms of gas dissolution and adsorption in the semi-liquid layer of organic matter. The mathematical model for this phenomenon is based on dynamic adsorption experiments with a constant pressure condition. The general and approximate solutions for the DAD model are obtained to estimate the physical parameters through a multilevel single-linkage method. From the fitting results of the DAD method, it is found that the absolute permeability begins to decrease when particles are crushed into smaller sizes and observed that particle size plays more important role than permeability in the diffusion process for crushed shale samples. Isotherm measurements for total gas and free gas reveal that the difference in gas content between total gas and adsorbed gas become greater as pressure increases. Sensitivity analyses for the model disclose that the apparent diffusion coefficient and adsorption/desorption rate coefficient determine gas transport and storage processes together. Analysis and comparison of a diffusion model, an instantaneous adsorption–diffusion (IAD) model, and the DAD model reveal that the former two models are special forms of the DAD model, and the sequence of equilibrium times required for the gas transport and storage processes is: DAD>IAD>diffusion model.

Measurement of dynamic adsorption–diffusion process of methane in shale

Shale gas is becoming an increasingly important energy resource in recent years. Identifying the gas transport process in a shale matrix is therefore of great importance in designing development strategies and in formulating the appropriate predictive mathematical models. Experimental and numerical investigations were conducted to study gas transport in shale. This paper presents the experimental work and obtains two characteristic parameters from the test results which will be utilized to serve the numerical work. Of great relevance to field development and management is knowing the contribution of each gas source to gas transport history and to ultimate gas recovery. Shale samples from Sichuan Basin in China were studied at designed conditions to test the effect of boundary pressure, temperature, particle size, and total organic content (TOC) on the dynamic adsorption–diffusion process. The tests for crushed shale samples were conducted at 35°C, 40°C, and 45°C, and at test pressures up to 17MPag. By plotting a curve describing the gas volume change per unit mass at standard condition over time (Vad), the adsorption–diffusion process at isothermal and constant boundary pressure (ICBP) was investigated and interpreted. These results indicate that both higher pressures and higher temperatures could promote a faster adsorption–diffusion rate, thus could promote a greater adsorption constant rate. Higher temperatures caused less gas to be adsorbed into the shale particles. Under the same experimental conditions, a difference in particle size showed no influence on the amount of gas adsorbed, but had a significant effect on the dynamic adsorption–diffusion process: the processing time extended linearly with the diameter of the particle size.

Impact of rock fabric on water imbibition and salt diffusion in gas shales

Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, clay swelling and osmotic potential on imbibition behavior.We systematically measure and compare the imbibition rates of deionized water and oil into wet/dry and confined/unconfined rock samples from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that initial water saturation decreases the water uptake of shale samples. However, it has no effect on oil imbibition rates. The liquid imbibition and ion diffusion rates along the lamination are higher than those against the lamination. The results also suggest that confining the shale samples decreases the water imbibition rate, parallel to the lamination. However, it has a negligible effect on water uptake, perpendicular to the lamination. Furthermore, confining does not significantly affect the ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. However, previous experiments on crushed shale samples show that the oil uptake of crushed packs is higher than their water uptake (Xu and Dehghanpour, 2014). The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by BSE images and complete spreading of oil on fresh break surfaces of the rock.

Effects of physical sorption and chemical reactions of CO2 in shaly caprocks

Abstract A comprehensive experimental approach has been used to assess the interrelation of CO 2 -mediated chemical reactions and transport properties in pelitic rocks. Sorption values on shale samples (P ∘ C) were high with maximum amounts of ∼44 kg/t. These capacities did not correlate with the organic carbon content, indicating sorption on and/or reaction with mineral components. Further, crushed shale samples were exposed to CO 2 in the presence of water at 15 MPa and 50 ∘ C for different time periods, showing significant changes in mineral composition. Reaction equilibrium was reached within periods of less than a month. Some of the caprock lithotypes could represent a significant sink for CO 2 deposited in the subsurface and could reduce the risk of leakage to the surface.